PRODUCTION OPTIMIZATION OF A MULTI-WELL GAS LIFT OPERATION
1.1.1. Oil Recovery
Crude oil accumulates over geological time in porous underground rock formations called reservoirs, where it has been trapped by overlying and adjacent impermeable rock. The oil resides together with water and free gas in very small holes (pore spaces) and fractures. To drive the oil to the surface energy is always required. When this energy is derived solely from the reservoir, the recovery process is referred to as primary recovery.
Primary oil recovery depends upon natural reservoir energy to drive the oil through the complex pore network to producing wells. Such driving energy can be derived from one or any of these processes: dissolved gas drive, gas cap drive, and water drive. In dissolved gas drive, the propulsive force is the gas in solution in the oil, which tends to come out of solution because of the pressure release at the point of penetration of a well. Dissolved gas drive is the least efficient type of natural drive.
In a situation where gas overlies the oil beneath the top of the trap, significant energy can be tapped from the compressed gas cap. The third and most efficient source of primary recovery energy is natural water drive.
The actual energy that causes a well to produce oil results from a reduction in pressure between the reservoir and the producing facilities on the surface. If the pressures in the reservoir and the wellbore are allowed to equalize, either because of a decrease in reservoir pressure or an increase in wellbore and surface pressure, no flow from the reservoir will take place and there will be no production from the well.
1.1.2. Artificial Lift
In order to support wells that do not have sufficient reservoir energy to raise fluid to the surface, an artificial lift is installed. Moreover, it also serves to supplement natural reservoir drive in boosting fluid production rate. There are six modes of artificial lift, namely
· Reciprocating Rod Lift System
· Progressing Cavity Pumping System
· Hydraulic Lift System
· Gas Lift System
· Plunger Lift System
· Electric Submersible Pumping System
1.1.3. Gas Lift System
Gas lift is the form of artificial lift that most closely resembles the natural flow process. It can be considered an extension of the natural flow process. In a natural flow well, as the fluid travels upward toward the surface, the fluid column pressure is reduced, gas comes out of solution, and the free gas expands. The free gas, being lighter than the oil it displaces, reduces the density of the flowing fluid and further reduces the weight of the fluid column above the formation. This reduction in the fluid column weight produces the pressure differential between the wellbore and the reservoir that causes the well to flow (API, 1994).
In a nutshell, gas lift can be used to efficiently and effectively accomplish the following objectives:
1. To enable wells that will not flow naturally to produce.
2. To increase production rates in flowing wells.
3. To unload a well that will later flow naturally.
4. To remove or unload fluids from wells to keep the gas well unloaded.
The gas lift system accomplishes its objectives by lightening the fluid column along the tubing, displacing liquid slug in the tubing and by expansion.
Figure 1 – The effects of lift gas in a well (Source: API Gas Lift Manual)
1.1.4. Advantages and limitations of gas lift system
The gas lift system happens to be the most commonly used artificial lift due to its uniqueness that cannot be matched by others (Eduardo and Augusto, 2007, p.2).
First, the initial and operational costs of downhole gas lift equipment are usually low. Flexibility cannot be equalled by any other form of lift. Installations can be designed for lifting initially from near the surface and for lifting from near total depth at depletion. Gas lift installations can be designed to lift from one to many thousands of barrels per day. In addition, the producing rate can be controlled at the surface. It is suitable for sand producing reservoir since it does not affect gas lift equipment in most installation. Moreover, gas lift is not adversely affected by deviation of the wellbore. Also, it has a long service life due to its few relatively moving parts. The major item of equipment (the gas compressor) in a gas lift system is installed on the surface where it can be easily inspected, repaired and maintained. This equipment can be driven by either gas or electricity. Furthermore, its key component – gas lift valve – is wireline retrievable. Lastly, multiple well production can be made from a single compressor and it can be effectively used in multiple or slim hole completion
Despite the robustness of the gas lift system, it still has some inadequacies. In API gas lift manual (1994), the snags were summarized as follows:
1. Availability of lift gas. In earlier years air lift continued in use for lifting oil from wells by many operators, but it was not until the mid-1920's that natural gas for lifting fluid became more widely available. Natural Gas, being lighter than air, gave better performance than air, lessened the hazards created by air when exposed to combustible materials and decreased equipment deterioration caused by oxidation. However, the gas is sometimes in limited quantities.
2. Limitation to the location of a central source of high pressure gas as a result of wide well spacing.
3. Possibility of increase operation cost if lift gas happens to be corrosive. The additional cost will be incurred from gas treatment.
4. Conversion of old wells to gas can require a higher level of casing integrity than would not be required for pumping systems.
1.1.5. Closed Rotative Gas Lift System
In most gas lift system, the lift gas is designed to recirculate. The gas which flows from the separator at low pressure is piped to the suction of a compressor station. The compressor basically boosts the pressure of the gas discharging it as a high-pressure gas. The high-pressure gas is then injected into the tubing in order to artificially lift fluid to the surface. Excess gas may be sold, injected into formation or flared. The figure (Figure 2) below vividly depicts the system.
Figure 2 – A closed rotative gas lift system (Source: Schlumberger Gas Lift Design and Technology)
1.1.6. Type of Gas Lift
The gas lift system type will be determined by the most effective gas lift method, continuous or intermittent. Choice is based on the well and gas distribution system conditions: producing rate and tubing diameter, static bottom-hole pressure (SBHP), productivity index (PI), gas piping diameter, and gas injection pressure and available rate.
1.1.7. Continuous Gas Lift
Continuous gas lift requires constant injection of high pressure gas into a flowing fluid column in order to reduce mixture density, lower flowing bottom-hole pressure (FBHP) and ultimately increase the production from the well.
Continuous gas lift is best for most wells, especially for high capacity wells in which FBHP pulsations must be minimized because of sand, gas, or water production, or due to reservoir gas or water coning. When gas is injected into the tubing, the fluid gradient becomes lighter from the point of gas injection to the surface. This reduces the FBHP and creates the drawdown needed for a higher production rate.
The flowing bottom-hole pressure (FBHP) is a function of the flowing pressure gradient above the point of gas injection, formation pressure fluid pressure gradient below the point of injection and flowing well back pressure.
Figure 3 – Flowing and static gas lift gradient of a continuous gas lift well (Source: API Recommended Practice)
1.1.8. Intermittent Gas Lift
Intermittent gas lift applies large rates of gas for some short-time duration. The production cycle consists of a liquid slug followed by a gas slug, followed by tail gas until the intermittent cycle is repeated. The large rate of gas and low rate of liquid causes the flowing gradient to be approximately 0.05 psi/ft, after the slugs have surfaced, thus the method is applicable to low SBHP wells. The injection gas can be controlled by a choke or by a control valve.
Intermittent gas lift should be applied to low rate wells, caused by high SBHP but low PI, or by low SBHP but high PI. Intermittent lift should incorporate tubing flow and injection pressure operated (IPO) unloading valves, with a large ported pilot operating valve.
Figure 4 – Intermittent Lift Cycle (Source: API Recommended Practice)
1.1.9. Gas Lift Valve
Valve design and type is related to the operating gas pressure and depth of injection. A typical gas lift valve may have an unbalanced nitrogen-charged bellows, spring or both inside the bellows. Gas lift valve bellows set pressures is based on the highest available kickoff or unloading injection pressure in order to achieve deep injection. It should be noted that kickoff pressure is the highest pressure available at the wellhead (casing) that can be used to start the unloading of dead completion or workover fluids in the casing and tubing.
Gas lift valves are placed in mandrels, which are run in the tubing string and are automatic in operation, opening and closing in response to preset pressures. Conventional mandrels are run on the tubing with the valve mounted on the exterior part of the mandrel before the string is run. A gas lift valve is designed to stay closed until certain conditions of pressure in the annulus and tubing are met. When the valve opens, it permits gas or fluid to pass from the casing annulus into the tubing. Mechanisms used to apply force to keep the valve closed are: (1) a metal bellows charged with gas under pressure, usually nitrogen; and/or (2) an evacuated metal bellows and a spring in compression. In both cases above, the operating pressure of the valve is adjusted at the surface before the valve is run into the well. All gas lift valves when installed are intended for one way flow, i.e. check valves are always included in series with the valve.
When the injection gas pressure creates the primary force on the bellows to open/operate valve, the valve is said to be injection pressure operated (IPO); but then if the valve is opened by forces from the tubing, the valve is production pressure operated.
Figure 5 – Modes of gas lift valve operation (Source: API Recommended Practice)
1.1.10. Gas Lift Design Considerations
Design, performance prediction, optimization, or trouble-shooting of a gas lift system requires data that includes: fluid PVT, producing pressure and temperature surveys, well testing production rates, gas lift valve characteristics, and constraints such as injection gas pressure and rate together with back pressure against the wall.
Gas lift design follows a systems analysis approach, in which pressures at various key points are determined for the desired production rate and different gas-liquid-ratio (GLR) values. The sequences of steps may vary, depending on which system parameters are known, and which are to be determined. The two most fundamental design issues are:
· How much gas to inject?
· At what depth(s) to inject it?
The above questions can only be answered if we can precisely determine how a well is likely to perform under different operating conditions.
1.1.11. Gas Lift Optimization
Normally oil production increases as gas injection increases. However, the gas injection has an optimum limit because too much gas injection will cause slippage, where gas phase moves faster than liquid, so that it reduces oil production. The main interest of gas lift optimization problem is to identify optimal gas injection allocation such that maximizes oil production or profit. In real problem, oil is produced from an oil field consisting of a group of gas lift wells (Saepudin et al, 2008).
One goal of well management is to optimally allocate available lift gas to targeted wells or risers to maximize hydrocarbon production under various facility constraints. Furthermore, as the market price of gas continues to increase and produced-water treatment becomes more expensive as a result of stricter environment regulations, it is desirable to maximize the overall profit rather than just production (Lu and Fleming, 2012).
Optimization is based on knowledge of the wells’ and system behaviour and the ability to change the behaviour to improve oil production with the available gas. Optimization cannot be attained with computer programs alone, but the computer models are a key tool when well data and fluid property data are accurate and used to simulate the well and system behaviour.
This research work is centred on developing an efficient procedure that can be utilised in optimizing profit from oil production in a multi-well gas lift system. The ultimate goal is to maximize profit with limited amount of lift gas which is to be allocated to a group of well on a continuous basis.
In addition, a Matlab-based software that implements the proposed model will be developed.
The following communicates the essence of embarking on this research:
· Optimum allocation of lift gas gives the maximum payoff that can be derived from investing into gas lift operation.
· Optimum allocation of lift gas can tremendously minimize operational and capital cost of lifting crude oil.
· Implementing an automatic control system for allocating lift gas to a field of oil wells requires a well calculated optimization scheme.
· It serves as a source of data that will help to decide whether to embark on gas lift operation or to go for other alternatives.
This study is limited to oil fields where back pressure and other factors that promote interactions among wells are not significant.